Electric Subsea Coiled Tubing Injector Apparatus

ABSTRACT

A subsea coiled tubing injector apparatus is disclosed. The subsea coiled tubing injector apparatus includes a linear actuator and a pair of carriages coupled via the linear actuator. The linear actuator is electrically powered and is configured to apply lateral force to the carriages. The carriages are configured to move substantially laterally with respect to one another. Each carriage includes a tubing engagement assembly configured to engage tubing interposed between the carriages.

BACKGROUND

The present disclosure relates to use of coiled tubing in the oil industry, and, more particularly, to an electric subsea coiled tubing injector apparatus.

Coiled tubing generally includes cylindrical tubing made of metal or composite. The continuous length of coiled tubing is a flexible product, typically several thousand feet long and wound on a reel. Coiled tubing may be introduced into an oil or gas well bore or pipeline through wellhead control equipment to perform various tasks during the exploration, drilling, production, and workover of the well/pipeline. Coiled tubing may be used, for example, to inject gas or other fluids into the well bore or pipeline, to inflate or activate bridges and packers, to transport tools downhole such as logging tools, to perform remedial cementing and clean-out operations in the bore, to deliver drilling tools downhole, for electric wireline logging and perforating, drilling, wellbore cleanout, fishing, setting and retrieving tools, for displacing fluids, and for transmitting hydraulic power into the well.

Coiled tubing is often used for offshore well operations. Offshore coiled tubing systems typically involve equipment with hydraulic elements. For example, coiled tubing systems may use fluids, such as mineral-based, oil-based, or glycol-based fluids, in conjunction with various equipment, such as hydraulic motors and hydraulic beam cylinders. However, using hydraulic elements in a subsea environment can be problematic. Hydraulic elements are vulnerable to subsea conditions such as temperature and pressure. At greater depths and pressures, a hydraulic-based system is subject to greater hydrostatic pressure on the equipment that requires compensation, such as gear compensation and sealing of bearings and other elements. At colder temperatures, the viscosity of fluids is increased. The potential for leaks and spills from equipment, such as fittings, hoses and other connections, is likewise increased. Thus, the problems with hydraulic-based systems include depth limitations and leak potential. These and other issues make hydraulic-based systems less desirable for subsea well operations.

SUMMARY

The present disclosure relates to use of coiled tubing in the oil industry, and, more particularly, to an electric subsea coiled tubing injector apparatus.

In one aspect, a subsea coiled tubing injector apparatus is disclosed. The subsea coiled tubing injector apparatus includes a linear actuator and a pair of carriages coupled via the linear actuator. The linear actuator is electrically powered and is configured to apply lateral force to the carriages. The carriages are configured to move substantially laterally with respect to one another. Each carriage includes a tubing engagement assembly configured to engage tubing interposed between the carriages.

In another aspect, a electrically powered subsea tubing injector is disclosed. The electrically powered subsea tubing injector includes a plurality of carriages. The carriages are linked by a plurality of actuators adapted to move the carriages. The actuators are electrically powered. A chain drive assembly coupled to each carriage. An electrically powered chain drive motor attached to each carriage. The carriages, actuators, chain drive assembly and chain drive motors are configured to cooperate to engage and move tubing without using hydraulic power.

In yet another aspect, a method of injecting coiled tubing into subsea wellbore is disclosed. The method includes aligning an electrically powered subsea tubing injector with a wellbore. The tubing injector includes a plurality of carriages. The carriages are linked by a plurality of actuators adapted to move the carriages. The actuators are electrically powered. The tubing injector also includes a chain drive assembly coupled to each carriage and an electrically powered chain drive motor attached to each carriage. The carriages, actuators, chain drive assembly and chain drive motors are configured to cooperate to engage and move tubing. The method also includes engaging tubing with the subsea tubing injector and inserting the tubing into the wellbore with the subsea tubing injector. The method is performed without using hydraulic power.

The features and advantages of the present disclosure will be readily apparent to those skilled in the art. While embodiments of this disclosure have been depicted and described and are defined by reference to exemplary embodiments of the disclosure, such references do not imply a limitation on the disclosure, and no such limitation is to be inferred. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those skilled in the pertinent art and having the benefit of this disclosure. The depicted and described embodiments of this disclosure are examples only, and not exhaustive of the scope of the disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the present embodiments and advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings, in which like reference numbers indicate like features.

FIG. 1 is a cross-sectional, side view of a coil tubing handling system in accordance with certain embodiments of the present disclosure.

FIG. 2 shows a partial schematic perspective of the inner side of a carriage, with the tracks and chains removed, in accordance with certain embodiments of the present disclosure.

FIG. 3 shoes a schematic front view of carriages in accordance with certain embodiments of the present disclosure.

FIG. 4 shows a side view of a subsea linear actuator according to certain embodiments of the present disclosure.

FIG. 5 shows a schematic of electrical connections for an injector apparatus according to certain embodiments of the present disclosure.

Accordingly, the present disclosure provides for a coiled tubing injector apparatus that is useable at greater subsea depths and pressures than those achievable with conventional injectors. A coiled tubing injector apparatus that is electrically powered, rather that hydraulically-power, also minimizes leak potential. These and other issues make electrically powered coiled tubing injector apparatuses according to the present disclosure more desirable for subsea well operations.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present disclosure relates to use of coiled tubing in the oil industry, and, more particularly, to an electric subsea coiled tubing injector apparatus.

Illustrative embodiments of the present disclosure are described in detail herein. In the interest of clarity, not all features of an actual implementation are described in this specification. Further details of implementing the present disclosure may be described in U.S. Pat. No. 6,209,634, the details of which are incorporated herein by reference. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve developers' specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of the present disclosure.

Shown in FIG. 1 is a cross-sectional, side view of a coiled tubing handling system 100. The system 100 may include a reel 105 for storing and deploying coiled tubing 115, as well as a tubing injector apparatus 110. The reel 105 may store thousands of feet of tubing 115. The outer diameters of tubing 115 may range from approximately one inch (2.5 cm) or less to approximately five inches (12.5 cm) or more. The reel 105 may be located near the sea surface—for example, on a seagoing vessel or a platform. The tubing injector apparatus 110 may be lowered from a near the sea surface, with a deployment system (not shown) known in the art, and may be located on the sea floor. The injector apparatus 110 may include a frame 112, may be mounted above a wellhead 135, and may be aligned along an axis of the well bore or pipeline 125. The injector apparatus 110 may push/pull the tubing 115 in/out the well bore 125 with an engagement assembly. Although the injector apparatus 110 is shown to interface a well bore/pipeline with a substantially vertical longitudinal axis, the orientation depicted is exemplary. In alternative embodiments, the injector apparatus 110 may be adapted to interface well bores/pipelines having other orientations. For example, the injector apparatus 110 may be adapted to interface pipelines that lay in a substantially horizontal direction relative to the sea floor.

The tubing 115 may extend from the reel 105 and into the injector apparatus 110. The reel 105 may rotate on an axle 120. The reel 105 may be part of a reel assembly, which, though not depicted in FIG. 1, may include a cradle for supporting the reel, a gooseneck, a drive motor, and a rotary coupling. The drive motor may be rotary coupled to the reel 105. The rotary coupling may provide an interface between a fluid line from the pump and the reel 105. When the tubing 115 is introduced into a well bore 125, the tubing injector apparatus 110 may draw the tubing 115 stored on the reel 105 and inject the tubing 115 into a wellhead 135. The drive motor may rotate the reel 105 to pay out the tubing 115 and the gooseneck may aid in directing the tubing 115 toward the tubing injector apparatus 110. Fluids may be pumped through the tubing 115 by a pump (not shown) that is fluidly connected to the tubing 115 through the reel 105.

The injector apparatus 110 may include a pair of carriages 140. In alternative embodiments, the injector apparatus 110 may include a different number of carriages. The injector apparatus 110, for example, may be adapted to include three or four carriages.

The carriages 140 may be slidably and/or pivotably coupled to the frame 112 of the injector apparatus 110 in order to allow for lateral movement. For example, each of carriages 140 may be slidably coupled at its base to the frame 112 with lugs. The base frame 112 may have a pair of attachment lugs extending upwardly therefrom. The attachment lugs may mate with corresponding carriage lugs located at a lower end of the carriages 140. The carriages 140 may be attached to the frame 112 with a load pin extending through the attachment lugs and corresponding carriage lugs. The attachment lugs may be slidably connected to the frame 112, so that the carriages 140 are laterally movable with respect to the frame 112 and to each other.

Each carriage 140 may include a chain drive system 145. The chain drive system 145 may include a plurality of opposing tracks 130. The tracks 130 may include endless drive chains arranged in a common plane. Alternative embodiments may include a different number and arrangement of tracks 130 than that illustrated in FIG. 1.

FIG. 2 shows a partial schematic perspective of the inner side of a carriage with the tracks and chains removed. FIG. 3 shows a front view of the carriages. Referring to FIGS. 2 and 3, the tracks 130 each may have a plurality of treaded paddles or gripper elements 132 that engage the tubing 115. Because the tracks 130 are positioned on opposite sides of the tubing 115, the tubing 115 may be squeezed between the opposing tracks 130. A direct drive electric motor 165, coupled to the tracks 130 via linkage elements including sprockets, may drive the tracks 130 so that the tracks 130 may sequentially engage the tubing 115. When the tracks 130 are in motion, each chain has a gripper element 132 contacting the tubing 115 as another gripper element 132 on the same chain is breaking contact with the tubing 115. The sequential engagement may continue as the tubing 115 is pushed into or pulled out of the wellbore 125.

The gripper elements 132 may be adapted for engaging coiled tubing 115 and moving it through apparatus 110, when a gripping force is applied to the tubing by the gripper elements 132. The gripper elements 132 may have an inner face and may contact an outer diameter of tubing 115. The gripper elements 132 may have a V-shaped groove for engaging tubing 115.

Each chain drive system 145 may include chain drive sprockets 150 in the carriage 140. The sprockets 150 may be mounted on a shaft 155. Shaft 112 may extend through an upper mounting boss on the forward side of the apparatus and into to a flanged bearing. A bearing adapter may also be included and attached to the upper mounting boss.

The chain drive system may also includes a pair of spaced idler sprockets 152 which are rotatably disposed in the lower end of the carriage. The idler sprockets may be mounted on a shaft 154. Chain tensioners may be connected to the opposite ends of shaft 154. The tensioners may be mounted so that they can be vertically adjusted within rectangular openings of outer plates of the carriage. The tracks 130, which may include a chain, may be engaged with drive sprockets 150 and idler sprockets 152 in each carriage. The tracks 130 may be of a kind known in the art and have a plurality of outwardly facing gripper blocks 132 disposed thereon.

A roller chain drive system 149 may be rigidly positioned in each carriage between the outer plates. Roller chain drive system 149 may include a linear or pressure beam 147 rigidly fixed to the outer plates of the carriage. As is known in the art, the linear beam 147 may be comprised of a linear beam frame with a bearing plate attached thereto. The linear beam 147 may be rigidly attached to the carriage.

A pair of spaced lower, or second roller chain sprockets 148 may be rotatably disposed on a lower end of the linear beam 147. A corresponding pair of spaced upper, or first roller chain sprockets may be rotatably disposed on an upper end of linear beam 147. The upper and lower sprockets may be mounted on bearings supported by shafts. A roller chain 149 may engage the upper and lower roller chain sprockets. The roller chain 149 may have an outer side which will engage an inner side of a chain of tracks 130. The lower sprockets may incorporate a tensioner, of a type known in the art to keep the proper tension on roller chain 149. The injector apparatus 110 may include various other linkage elements which are known in the art and employed with conventional coiled tubing injectors.

In a conventional tubing injector, the sprockets 150 are driven by a reversible hydraulic motor, which may be of a type known in the art, may be driven by a planetary gear, and may include an integral brake. By contrast, as illustrated in FIG. 2, certain embodiments of the present disclosure may include a direct drive electric motor 165 coupled to the shaft 155 and sprockets 150 of each carriage 140, in lieu of using hydraulic motors and planetary gearboxes. In certain embodiments, the direct drive electric motor 165 may be bolted directly to the shaft 155 and sprockets 150. The direct drive electric motors 165 may inject, retract or suspend tubing 115 in a well.

The drive electric motors 165 may have the capabilities of driving the chain drive system 145 in similar fashion to a hydraulic motor implementation, but without the attendant problematic issues of hydraulics. The drive electric motors 165 may be capable of operating in subsea conditions to depths of 10,000 feet or more. This allows the injector apparatus 110 to operate in a subsea environment without having to deal with the effects of hydrostatic pressure on hydraulic components. The electric drive system also removes the potential of hydraulic spills into the sea through leaks or failures.

The injector apparatus 110 also includes linear actuators 170 for moving the carriages 140 with respect to one another. In certain exemplary embodiments, as illustrated in FIGS. 1-3 and 5, four linear actuators 170 may be employed. In other embodiments, a different number of linear actuators 170 may be employed. Actuator mounting plates 171 may have lugs 172 extending therefrom and rigidly mounted to the outer plates of the carriages. The ends of actuators 170 may be attached to lugs 172. Mounting plates 171 may be attached utilizing bolts extending through the mounting plates and the outer plates of the carriage. Bolts may also extend through side webs of the linear beam to rigidly attach the linear beam to the outer plates.

FIG. 4 shows a side view of one embodiment of a subsea linear actuator. The linear actuator 170 may be attached to one carriage at end 171. The linear actuator 170 may be attached to another carriage at another point, which in certain embodiments may be at end 172 and in certain embodiments may be at another point 173 that is more toward the middle of linear actuator 170. The linear actuators 170 may be electrically powered, e.g., via subsea connector 172, and may be capable of operating in subsea conditions to depths of 10,000 feet or more. The linear actuator 170 may be coupled to one or more pressure compensators 175 configured to allow the internal pressure in the electric motors of linear actuators 170 to be equalized with ambient pressures. The linear actuators 170 accordingly may provide the force on the tubing necessary for tracks 130 to cooperatively inject, retract, or hold the tubing 115. The linear actuators 170 thus may have the capabilities of hydraulic cylinders, but without the attendant problematic issues of hydraulics. The linear actuators 170 may include any subsea actuator capable of satisfactorily providing the force on the tubing necessary for tracks 130 to cooperatively inject, retract, or hold the tubing 115. In some embodiments, a manual actuator may be set at the surface so that, instead of the electric motor being coupled to the drive screw.

FIG. 5 shows a schematic of electrical connections for injector apparatus 110 according to certain embodiments of the present disclosure. In a subsea application, the electrical enclosure box 180 may include a connection terminal 185 with the capabilities of connecting to power the systems within the injector apparatus 110. Motor power cables 185 may electrically couple the direct drive electric motors 165 to the enclosure box 180. Actuator power cables 190 may electrically couple the linear actuators 170 to the enclosure box 180. In certain embodiments, enclosure box 180 may be firmly attached to a portion of the injector apparatus 110, such as frame 112. Accordingly, the enclosure box 180 may act as a junction box for connections of the direct drive electric motors 165 and the linear actuators 170. The enclosure box 180 may include any means capable of satisfactorily terminating the electrical connections for the purpose of connection to the surface. The enclosure box 180 may further include an umbilical terminal 210 coupling the enclosure box 180 to an umbilical line 215. The umbilical line 215 may extend toward the sea surface and be adapted for the transmission of power, control signals, and/or data.

Umbilical line 215 may include one or more umbilical lines providing transmission of power necessary to drive the direct drive electric motors 165, the linear actuators 170, and other devices. Umbilical line 215 may include multiple conductors. The umbilical line 215 may include a conduit with the electrical connections molded into one member. By way of example without limitation, the conduit may be a 2″ OD (outside diameter) coiled tubing. Conduit may provide the means to take returns through the coiled tubing and also provide power from a power source located at or near the sea surface.

In some embodiments, the enclosure box 180 may contain control circuits configured to allow safe operation of the injector speed and motor operation. In some embodiments, the enclosure box 180 may contain wireless transmission means used for transceiving signals to/from the surface, e.g., for communication of control signals and/or data associated with the injector and/or well bore. In some embodiments, the enclosure box 180 may be further adapted to interface with peripheral devices, such as a remotely operated underwater vehicle (ROV), that may receive power via the umbilical line 215. In some embodiments, the enclosure box 180 may be further adapted to allow a peripheral device, such as a ROV, may control and/or power the injector apparatus 110.

The injector apparatus 110 may also include load cells 195 and/or a depth counter 200. The enclosure box 180 may be further coupled to the injector apparatus 110 via data cables 205, which may allow for the transmission of load cell information and/or depth information. In alternative embodiments, as would be appreciated by one of ordinary skill in the art having the benefit of this disclosure, data communication may be alternatively achieved via other means, such as wireless means.

Accordingly, the present disclosure provides for a coiled tubing injector apparatus that is useable at greater subsea depths and pressures than those achievable with conventional injectors. A coiled tubing injector apparatus that is electrically powered, rather that hydraulically-power, also minimizes leak potential. These and other issues make electrically powered coiled tubing injector apparatuses according to the present disclosure more desirable for subsea well operations.

Therefore, the present disclosure is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. 

1. A subsea coiled tubing injector apparatus comprising: a linear actuator; and a pair of carriages coupled via the linear actuator; wherein the linear actuator is electrically powered and is configured to apply lateral force to the carriages; wherein the carriages are configured to move substantially laterally with respect to one another; and wherein each carriage comprises a tubing engagement assembly configured to engage tubing interposed between the carriages.
 2. The electric coiled tubing injector apparatus of claim 1, further comprising: an electrically powered motor operatively coupled to, and configured to drive, the tubing engagement assembly.
 3. The electric coiled tubing injector apparatus of claim 2, further comprising: a frame, wherein the carriages are coupled to the frame, and wherein the carriages are configured to move substantially laterally with respect to one another.
 4. The electric coiled tubing injector apparatus of claim 3, wherein the carriages are pivotably coupled to the frame.
 5. The electric coiled tubing injector apparatus of claim 2, further comprising: a pressure compensator coupled to the electrically powered motor, where the pressure compensator is configured to change an internal pressure of the electrically powered motor.
 6. The electric coiled tubing injector apparatus of claim 5, wherein the pressure compensator is further configured to at least substantially equalize an internal pressure of the electrically powered motor with respect to an ambient pressure.
 7. The electric coiled tubing injector apparatus of claim 1, further comprising: a pressure compensator configured to change an internal pressure of the linear actuator.
 8. The electric coiled tubing injector apparatus of claim 8, wherein the pressure compensator is further configured to at least substantially equalize an internal pressure of the linear actuator with respect to an ambient pressure.
 9. The electric coiled tubing injector apparatus of claim 2, further comprising: an umbilical line coupled to one or more of the linear actuators and the electrically powered motor, where the umbilical line is configured to electrically couple one or more of the linear actuator and the electrically powered motor to a power source at location corresponding to a surface of a body of water.
 10. A electrically powered subsea tubing injector comprising: a plurality of carriages, where the carriages are linked by a plurality of actuators adapted to move the carriages, and where the actuators are electrically powered; a chain drive assembly coupled to each carriage; and an electrically powered chain drive motor attached to each carriage; wherein the carriages, actuators, chain drive assembly and chain drive motors are configured to cooperate to engage and move tubing without using hydraulic power.
 11. The electrically powered subsea tubing injector of claim 10, further comprising: a sprocket rotatably mounted on each carriage, wherein each sprocket is configured to transfer motive force the chain drive motor attached to the carriage to the chain drive assembly of the carriage.
 12. The electrically powered subsea tubing injector of claim 10, wherein the actuators and the chain drive motors are electrically coupled via an umbilical line to a source at location corresponding to a surface of a body of water.
 13. The electrically powered subsea tubing injector of claim 10, further comprising: a frame, wherein the carriages are coupled to the frame, and wherein the carriages are configured to move substantially laterally with respect to one another.
 14. The electrically powered subsea tubing injector of claim 13, wherein the carriages are pivotably coupled to the frame.
 15. The electrically powered subsea tubing injector of claim 10, further comprising: a pressure compensator coupled to each actuator, where the pressure compensator is configured to change an internal pressure of the actuator.
 16. The electrically powered subsea tubing injector of claim 10, further comprising: a pressure compensator coupled to each chain drive motors, where the pressure compensator is configured to change an internal pressure of the chain drive motor.
 17. The electrically powered subsea tubing injector of claim 10, further comprising: an umbilical line coupled to each actuator and each chain drive motor, where the umbilical line is configured to electrically couple the actuators and the chain drive motors to a power source at a subsea location.
 18. The electrically powered subsea tubing injector of claim 17, wherein the umbilical line is further configured to transmit data signals.
 19. The electrically powered subsea tubing injector of claim 17, wherein the umbilical line is further configured to transmit control signals.
 20. A method of injecting coiled tubing into subsea wellbore, the method comprising: aligning an electrically powered subsea tubing injector with a wellbore, wherein the tubing injector comprises: a plurality of carriages, where the carriages are linked by a plurality of actuators adapted to move the carriages, and where the actuators are electrically powered; a chain drive assembly coupled to each carriage; and an electrically powered chain drive motor attached to each carriage; wherein the carriages, actuators, chain drive assembly and chain drive motors are configured to cooperate to engage and move tubing; engaging tubing with the subsea tubing injector; and inserting the tubing into the wellbore with the subsea tubing injector; wherein the method is performed without using hydraulic power. 